1. Field of the Invention
The present invention generally relates to methods and apparatus for using a formation tester to retrieve formation characteristics on a subterranean formation through a wellbore by acquiring pressure versus time response data in order to calculate formation pressure, permeability, and other formation characteristics. More particularly, the present invention relates to a method of acquiring said data from a formation tester disposed in a drill string configured to perform formation testing while drilling operations. More particularly still, the present invention relates to a method of compressing the amount of data transmitted to the surface during a formation testing while drilling operation to decrease the amount of time required to transmit the formation characteristic data.
2. Background of the Invention
In drilling and producing hydrocarbon wells, optimizing the performance of wells is essential. The acquisition of accurate data from the wellbore is critical to the optimization of the completion, production and/or rework of hydrocarbon wells. This wellbore data can be used to determine the location and quality of hydrocarbon reserves, whether the reserves can be produced through the wellbore, and for well control during drilling operations.
Well logging is a means of gathering data from subsurface formations by suspending measuring instruments within a wellbore and raising or lowering the instruments while measurements are made along the length of the wellbore. For example, data may be collected by lowering a measuring instrument into the wellbore using wireline logging, logging-while-drilling (LWD), or measurement-while-drilling (MWD) equipment. In wireline logging operations, the drill string is removed from the wellbore and measurement tools are lowered into the wellbore using a heavy cable that includes wires for providing power and control from the surface. In LWD and MWD operations, the measurement tools are integrated into the drill string and are ordinarily powered by batteries and controlled by either on-board and/or remote control systems. Regardless of the type of logging equipment used, the measurement tools normally acquire data from multiple depths along the length of the well. This data is processed to provide an informational picture, or log, of the formation, which is then used to, among other things, determine the location and quality of hydrocarbon reserves. One such measurement tool used to evaluate subsurface formations is a formation tester.
To understand the mechanics of formation testing, it is important to first understand how hydrocarbons are stored in subterranean formations. Hydrocarbons are not typically located in large underground pools, but are instead found within very small holes, or pore spaces, within certain types of rock. The ability of a rock formation to allow hydrocarbons to move between the pores, and consequently into a wellbore, is known as permeability. The viscosity of the oil is also an important parameter, and the permeability divided by the viscosity is termed “mobility” (k/μ). Similarly, the hydrocarbons contained within these formations are usually under pressure and it is important to determine the magnitude of that pressure in order to safely and efficiently produce the well.
During drilling operations, a wellbore is typically filled with a drilling fluid (“mud”), such as water, or a water-based or oil-based mud. The density of the drilling fluid can be increased by adding special solids that are suspended in the mud. Increasing the density of the drilling fluid increases the hydrostatic pressure that helps maintain the integrity of the wellbore and prevents unwanted formation fluids from entering the wellbore. The drilling fluid is continuously circulated during drilling operations. Over time, as some of the liquid portion of the mud flows into the formation, solids in the mud are deposited on the inner wall of the wellbore to form a mudcake.
The mudcake acts as a membrane between the wellbore, which is filled with drilling fluid, and the hydrocarbon formation. The mudcake also limits the migration of drilling fluids from the area of high hydrostatic pressure in the wellbore to the relatively low-pressure formation. Mudcakes typically range from about 0.25 to 0.5 inch thick, and polymeric mudcakes are often about 0.1 inch thick. On the formation side of the mudcake, the pressure gradually decreases to equalize with the pressure of the surrounding formation.
The structure and operation of a generic wireline formation tester are best explained by referring to FIG. 1. In a typical formation testing operation, a formation tester 500 is lowered on a wireline cable 501 to a desired depth within a wellbore 502. The wellbore 502 is filled with mud 504, and the wall of the wellbore 502 is coated with a mudcake 506. Because the inside of the tool is open to the well, hydrostatic pressure inside and outside the tool are equal. Once the formation tester 500 is at the desired depth, a probe 512 is extended to sealingly engage the wall of the wellbore 502 and the tester flow line 519 is isolated from the wellbore 502 by closing equalizer valve 514.
Formation tester 500 includes a flowline 519 in fluid communication with the formation and a pressure sensor 516 that can monitor the pressure of fluid in flowline 519 over time. From this pressure versus time data, the pressure and permeability of the formation can be determined. Techniques for determining the pressure and permeability of the formation from the pressure versus time data are discussed in U.S. Pat. No. 5,703,286, issued to Proett et al., and incorporated herein by reference for all purposes.
Whereas the above description is provided in the context of a wireline formation tester, the same concepts generally also apply to formation testing while drilling (FTWD) applications where the formation testing tool is disposed within a drill string. Given the costs of drilling downtime associated with removing a drill string and inserting a wireline tester into a borehole, it is clearly advantageous to perform testing and acquire formation characteristics while drilling. In the alternative, it is also desirable to acquire formation characteristic data during brief interruptions in drilling. In either case, with FTWD, the drill string does not have to be removed from a borehole and all data may be transmitted to the surface while the drill string remains in the borehole.
Unfortunately, FTWD tools disposed on drill strings do not generally include transmission paths for transmitting data to and receiving data from the surface. Communication links such as data cables, fiber optic cables, or RF transceivers are simply not present in conventional drill strings. However, there is still a need to transmit the results of a FTWD or LWD operation back to the surface. This problem is not new in the art. It has long been recognized in the oil and gas industry that communicating between the surface equipment and the subsurface drilling assembly is both desirable and necessary.
Uplink and downlink signaling, or communicating between surface equipment and a drilling assembly, is typically performed to provide instructions in the form of commands to the drilling assembly and for transmitting logging data to the surface. For example, in a directional drilling operation, downlink signals may instruct the drilling apparatus to alter the direction of the drill bit by a particular angle or to change the direction of the tool face. Uplink signaling, or communicating between the drilling assembly and the surface equipment, is typically performed to verify the downlink instructions and to communicate data measured downhole during drilling to provide valuable information to the drilling operator.
A common method of downlink signaling is through mud pulse telemetry. When drilling a well, fluid is pumped downhole such that a downhole receiver within the drilling assembly can measure the pressure and/or flowrate of that fluid. Mud pulse telemetry is a method of sending signals by creating a series of momentary pressure changes, or pulses, in the drilling fluid, which can be detected by a receiver. For downlink signaling, the pattern of pressure pulses, including the pulse duration, amplitude, and time between pulses, is detected by the downhole receiver and then interpreted as a particular instruction to the downhole assembly.
The use of mud pulse telemetry as a communication means is well known to those skilled in the art. Representative examples of mud pulse telemetry systems may be found in U.S. Pat. Nos. 3,949,354, 3,958,217, 4,216,536, 4,401,134, 4,515,225 and 5,113,379. An unfortunate limitation to mud pulse telemetry systems is that bandwidth is severely limited as compared to wireline data transmission systems. It is generally accepted by those skilled in the art that data transmission rates in mud pulse telemetry systems are on the order of about two bits per second.
The effects of this limitation may be understood by considering the representative formation test pressure timeline shown in FIG. 2, which shows a number of pressure samples taken at fixed time intervals during a formation pressure test. Specifically, the sampling scheme shown in FIG. 2 produces 50 discrete samples of the pressure curve, which includes transitions from a hydrostatic, pre-formation test condition to the point where the packer is set and the equalizer valve is closed, which, in the case of a proper seal, is characterized by an increased pressure. The formation test continues by pulling pressure in the formation tester down using a drawdown piston or some other equivalent pressure lowering means. Ideally, the drawdown cycle pulls pressure within the formation tester below the formation pressure to allow pressure within the formation tester to accurately rise to the formation pressure. Following the drawdown cycle, pressure within the formation tester is permitted to rise to the formation pressure without any inducement from external devices. That is, pressure rises naturally at a rate that is governed by the pressure gradient and by the mobility of the fluid in the formation. Ultimately, once the pressure in the formation tester converges on the formation pressure, a final pressure reading is taken before releasing the packer and pressure rises once again to the hydrostatic pressure that exists within the wellbore annulus.
In general, capturing the information in the pressure curve shown in FIG. 2 requires a sampling of pressure points at discrete times. These pressure samples are then subsequently converted to digital representations if the pressure sensor 516 is an analog device. The size of the digital words that represent each individual sample must be kept small enough and the time between samples must be kept far enough apart to allow the data to be transmitted real time. In general, these limitations are in contrast with the requirements for reconstructing a curve from digital samples. It is normally desirable to include samples with larger bit resolutions that are spaced close enough to each other to guarantee that all relevant pressure characteristics are transmitted uplink. Unfortunately, mud-pulse telemetry simply does not afford this luxury. With the two bit/second limitation, eight-bit word pressure samples may be transmitted no faster than every four seconds. In reality, bit resolutions must be even smaller and sample rates must be larger to account for packet headers and other transmission data. Consequently, the limitations imposed by mud-pulse telemetry impose significant restrictions on the quality of formation pressure data gathered during drilling operations.
The above generalizations have been described with the assumption that mud pumps are on, thereby implying that data can be transmitted real-time or near real-time using mud pulse telemetry. However, it may also be desirable to perform formation tests with all pumps off. Pump pulses may add noise to pressure measurements making it difficult to assess how accuracy of the measurements are affected. Thus, the quality of the pressure samples improves if external vibrations and pulses are temporarily terminated by turning all pumps off. If formation testing occurs with mud pumps off, the ability to communicate pressure data real-time ceases. Consequently, it becomes imperative that the relevant pressure data be transmitted immediately following a formation test, when the mud pumps are turned back on. Further, it is critical that said data be transmitted as quickly as possible.
Given the above problems associated with transmitting formation pressure data uplink from a wellbore to the surface, it would be desirable to transmit a compressed version of the pressure data that permits reconstruction of the relevant pressure curves. To achieve this, it would be advantageous to provide only critical pressure and timing information sufficient to relay formation characteristics. In addition, given the unreliable nature of most compression techniques, it would also be desirable to provide some indication of how accurately the compressed information matches the actual data samples taken downhole.